Environmental update - January 2006
By Roy Belden
New Source Review
The US Environmental Protection Agency took another significant step toward a complete overhaul of the federal “new source review” air permitting program.
The agency proposed a new rule in October that would dramatically alter how it calculates an emissions increase due to a physical change or a change in the method of operation at existing power plants. The proposed rule responds to a decision by the US court of appeals for the 4th circuit, which held that the agency must define the word “modification” consistently for purposes of both the new source review or “NSR” program and the new source performance standards or “NSPS” program. The proposed rule would clarify that power plant upgrades are not considered “modifications” for air permitting purposes unless they are considered modifications for purposes of the NSPS program.
The proposed emissions test would determine whether an emissions increase is expected to occur by comparing the maximum hourly emissions achievable at an electric generating unit during the past five years to the maximum hourly emissions achievable at the unit after the upgrades. Under the NSPS program, a “modification” occurs when there is an increase in the maximum achievable hourly emission rate.
This proposed approach is a significant development because it is much harder to trigger a “modification” at an existing power plant under the NSPS program than under the standard that EPA was using to calculate emissions increases under the NSR program. In the NSR program, a “modification” occurs when there is a significant increase in annual emissions at a plant compared to a base line of the plant’s actual emissions during a consecutive two-year period within the previous five years. Under the new proposed rule, upgrades to a boiler that restore the unit to its original hourly emission rate would not be a modification, but they would probably have been a modification under the old EPA rules for the NSR program.
The issue of how to determine whether a “modification” has occurred under the NSR program has been a source of conflict among EPA, the regulated community and environmental groups, and the issue came to a head in 2005 when two federal appeals courts reached opposite conclusions on how a “modification” is calculated under the NSR program. The US appeals court for the 4th circuit held in US v. Duke Energy Corp. in June that “modification” has the same meaning for purposes of both the NSR and NSPS programs. However, the US appeals court for the District of Columbia circuit ruled nine days later in New York v. EPA that the agency is free to define the word “modification” differently for NSR permits.
Meanwhile, EPA also invited comments on an alternative approach for calculating emissions increases from modifications that is not quite as far reaching as its preferred approach described above. The alternative is to measure emissions increases by comparing the maximum hourly emissions achieved before the upgrades to the maximum hourly emissions achieved after the upgrades. EPA is also requesting comment on whether the emissions test should be changed from a kg/hr calculation to a mass-of-emissions-per-unit-of-output calculation, such as pounds per megawatt hour or nanograms per joule. EPA says that using an output-based calculation should help encourage the use of more energy-efficient units that displace older, less efficient units.
The new proposed rule is highly controversial, and it is attracting significant opposition from public interest groups. Environmental groups complain that EPA is retreating from its obligation to enforce the NSR program. EPA extended the comment period on the proposed rule from December 19, 2005 to February 17, 2006. A public hearing took place on December 9. If the proposed rule is adopted, then the attorneys general for several northeastern and mid-Atlantic states are expected to file suit to block implementation of the new rule.
In addition, the EPA administrator, Stephen Johnson, has directed the agency’s enforcement personnel to “reprioritize resources to other areas” rather than pursue new high-profile NSR enforcement cases. The agency will continue its ongoing NSR enforcement actions against several major utilities with coal-fired plants, but its focus in the future will shift to pursuing companies that violate the new proposed rule.
The Environmental Protection Agency is reconsidering portions of two rules the agency issued in early 2005 to reduce mercury emissions from power plants.
Fourteen northeastern and mid-Atlantic states and five environmental groups sued to force the agency to reevaluate the clean air mercury rule and the so-called “section 112 revision rule” in which the agency reversed a December 2000 finding that the regulation of mercury from coal-fired plants is “necessary and appropriate.” EPA concluded that more recent information demonstrates that it is not appropriate or necessary to regulate mercury emissions from coal-fired power plants under section 112 of the Clean Air Act. Section 112 requires use of a “command-andcontrol” approach to regulating air toxic emissions instead of a more flexible emissions trading regime favored by the Bush administration.
EPA is reconsidering two issues under the section 112 revision rule. First, it is assessing whether the public should have had a chance to comment on some of the legal interpretations that it adopted for the first time in the final section 112 revision rule; they were not hinted at in the proposed rule on which the agency had requested comments. Second, it is assessing whether the public should have been given an additional opportunity to comment on how the rule will be applied based on certain conclusions reached by the agency. The litigants have a particular gripe about how the government has chosen to measure the amount of mercury in fish due to utility emissions and the conclusion that such levels are not reasonably anticipated to be hazardous to public health.
EPA is also reconsidering seven issues tied to the clean air mercury rule. They are the methodology used to apportion the mercury budget to the individual states, the definition of “designated pollutant,” EPA’s basis for subcategorizing subbituminous coal-fired units, the statistical analysis used to establish the new source performance standards, the calculation of the highest annual average of mercury in coal used to derive the new source performance standards, the definition of covered units to include municipal waste combustors, and expansion of the definition of covered units to include some industrial boilers.
The clean air mercury rule has come in for heavy criticism, and a number of lawsuits have been filed challenging it. The parties filing these suits want strict technology-based emission standards for mercury emissions under section 112 of the Clean Air Act.
The clean air mercury rule applies to coal-fired steam generating units with capacities of more than 25 megawatts and that sell more than 25 megawatts to the grid. The mercury rule also applies to cogeneration units capable of combusting more than 25 megawatts on an output basis and that put more than a third of their capacity and more than 25 megawatts into the utility grid for sale.
Under the clean air mercury rule, EPA has adopted a two-phased “cap-and-trade” approach to reduce mercury emissions from coal-fired plants starting with the first phase in 2010 and the second phase following in 2018. “Cap and trade” means that power plants have a choice of reducing pollution or buying emission allowances from other plant owners who have extra allowances. In addition to meeting the mercury emission caps, new coal-fired power plants that commence construction on or after January 30, 2004 will have to meet stringent “new source performance standards” for mercury emissions.
EPA has imposed a 38-ton mercury emission cap for the first phase and a 15-ton cap for the second phase. This is the amount of mercury emissions that would be allowed each year from all coal-fired power plants nationwide. US power plants emit approximately 48 tons a year of mercury in total. In both phase one and two, mercury allowances would be issued to coal-fired plants based on a unit’s share of the total heat input from existing coal units multiplied by an adjustment factor depending on the type of coal. One allowance will correspond to one ounce of mercury.
Even though the government has agreed with the northeastern and mid-Atlantic states and environmental groups to reconsider some issues behind its mercury rules, major changes to the rule are not expected.
The lawsuits challenging the mercury rules are moving ahead on a parallel track before the US appeals court in Washington DC, and a decision on the merits is not expected until late 2006 or early 2007.
In related news, an organization of state and local air pollution control officials unveiled a model mercury rule that states may consider as an alternative to the federal approach. Under the EPA rule, states have the option of participating in an EPA-managed cap-and-trade program or electing to adopt their own state programs. The model rule promoted by the state and local officials organization provides two options. The first option calls for an 80% reduction in mercury emissions by 2008, followed by a 90 to 95% reduction by 2012. The second option would require coal-fired power plants to reduce mercury emissions by 90 to 95% by 2008 with a possible four-year delay if pollution controls to reduce NOx (nitrogen oxide), SO2 (sulfur dioxide) and particulate matter are also installed. The EPA clean air mercury rule requires approximately a 50% nationwide reduction in mercury emissions by 2010 and about a 70% reduction by 2018. New Hampshire, New Jersey, Pennsylvania and other states are moving on their own to adopt mercury reduction standards that are more stringent than the clean air mercury rule. New Hampshire, for example, appears to be heading toward adopting an 80% reduction target by 2013. New Jersey has already adopted a mercury reduction target of 90% or 3.00 mg per megawatt hour by the end of 2007.
The Environmental Protection Agency released a final rule in November that explains what someone buying property must do to satisfy the “all appropriate inquiries” due diligence standard for recognizing certain defenses to potential Superfund liability associated with prior releases of hazardous substances. Under Superfund, liability may be imposed on a current “owner or operator” of a facility even if that entity did not contribute to pollution on a site.
The new “all appropriate inquiries” rule will take effect on November 1, 2006.
In the interim, EPA will recognize either compliance with the new rule or completion of a phase I environmental site assessment conducted as in the past.
There are three defenses under Superfund to potential liability based on satisfying the “all appropriate inquiries” due diligence standard. The defenses are provided for the following categories of landowners:“innocent landowner,” “contiguous property owner” and “bona fide prospective purchaser.”
Under Superfund, an “innocent landowner” may be protected from liability if he or she acquires property without the knowledge that it is contaminated or likely to be contaminated and the landowner is not affiliated with or a counterparty to a contract with the entity that caused the contamination (other than a contract for sale or a service contract). Likewise, a “contiguous property owner” who acquires property that is or may become contaminated by an offsite source may be protected from liability if he or she demonstrates not only a lack of knowledge, but also no reason to know that the property was or could be contaminated by a release of hazardous substances from a neighboring property. In order to meet the requirement that a contiguous property owner did not know about any potential contamination at the property, a phase I report satisfying the “all appropriate inquiries” standard must be performed.
Under the third available defense, a “bona fide prospective purchaser” must purchase the property after January 11, 2002, complete a phase I site assessment and not be affiliated with or be a counterparty to a contract with an entity that is responsible for the contamination. Nevertheless, a person may qualify as a bona fide prospective purchaser even if he or she purchases the property knowing that it is contaminated or might be contaminated from the offsite migration of contaminants.
In the preamble to the new rule, EPA confirmed that a phase I report meeting the “2005 ASTM phase I report standards” will fully comply with the new rule. Further, EPA also recognizes that phase I reports prepared in conformance with the rule will be valid for one year prior to the acquisition date. Phase I reports older than that will need to be updated within one year prior to the date the property is acquired.
Clean Air Interstate Rule
The Environmental Protection Agency announced in late November that it will reconsider four issues tied to the “clean air interstate rule.”The clean air interstate rule requires 28 eastern states and the District of Columbia to reduce nitrogen oxide, or NOx, and sulfur dioxide, or SO2, emissions from power plants and other pollution sources by 2015.
Several states, utilities and environmental groups filed petitions for reconsideration with EPA. Many of these same parties also filed lawsuits in the US appeals court in Washington challenging the rule. EPA will generally grant a petition for reconsideration if the petitioner can demonstrate that the objection is of central relevance to the rule and that it was impractical to raise the issue during the public comment period.
The first issue being reconsidered with whether there were inequities in the method used to apportion SO2 allowances to states that elect to use the EPA model SO2 trading rule. One petitioner argued that the allocation penalizes utilities with units that have lower emission rates because they may end up buying surplus allowances from utilities with high emission rate units that install pollution controls.
The second issue concerns EPA’s use of specific fuel adjustment factors to establish NOx budgets for each state. Several utilities argue that states that rely heavily on natural gas and oil to generate electricity are being required to make more significant reductions in NOx emissions than states that use coal. This is due to the way EPA granted greater weight in the fuel adjustment factors to states with more coal-fired units.
The third issue addresses the modeling inputs EPA used to determine whether Minnesota should be included in the PM2.5 portion of the clean air interstate rule. The fourth issue relates to whether Florida should be included in the ozone region under the rule.
The clean air interstate rule assigns each of the 28 affected states an emissions budget. Each state must comply in one of two ways. It can participate in an EPA-administered cap-and-trade program that ratchets down NOx and SO2 emissions from power plants in two stages starting with an initial NOx cap in 2009 and an SO2 cap in 2010 followed by lower caps for both pollutants in 2015. Alternatively, a state may propose other emission reduction measures, including roping in other sectors besides power plants to spread the reductions across a wider number of facilities.
EPA is accepting comments on the four issues through January 13, 2006. The agency expected to make decisions on the issues by March 15, 2006. Meanwhile, the lawsuits have been consolidated into a lead case titled North Carolina v. EPA, and a decision in the case is not expected until late 2006 or early 2007. The clean air interstate rule is generally expected to survive the legal challenges since it is modeled after a “NOx SIP call rule” that remained largely intact after a protracted legal battle.
The Environmental Protection Agency took steps in October to clarify various provisions of the pretreatment discharge standards for wastewater that is sent by industrial users to local wastewater treatment plants. The pretreatment discharge standards require municipalities to set discharge limits to control industrial discharges into local sewage collection systems.
The new rule removes certain nonessential process requirements, including an order to sample for pollutants that are not present at a particular industrial facility. Instead, the industrial plant will be granted a monitoring waiver upon certifying that the pollutants are not present. Under the final rule, municipalities will have greater authority to grant general pretreatment permits covering a category of sources and the ability to use best management practices as an alternative to numeric discharge limits. Municipalities are also granted the flexibility to approve alternative sampling techniques.
While industrial discharges will still have to meet the same federal discharge limits in the locally-enforced pretreatment programs, EPA believes that the rule changes will substantially reduce the compliance costs for industrial facilities. The rule became effective on November 14, 2005.
EPA released a new analysis in late October comparing the costs to implement the Bush administration’s “clear skies initiative” to the costs of several legislative alternatives pending in Congress. The analysis showed the clear skies proposal is the least expensive of the proposals at $5.7 billion in 2020 with expected annual health benefits of $114 to $134 billion by 2020. The costs of competing pollution control measures introduced by Senators James Jeffords (I-Vermont) and Thomas Carper (D-Delaware) were $50.8 billion and $9.5 billion, respectively, by 2020 with generally much higher anticipated annual health benefits. The administration is hoping that the new analysis will prompt Congress to move on its clear skies initiative. The initiative has remained stalled, and action on it remains unlikely.
In California, two lawsuits were filed with the Alameda County superior court challenging the issuance of new conditional use permits for more than 3,000 existing wind turbines in the Altamont Pass area. The 13-year permits, issued by the Alameda County board of supervisors, imposed new conditions to reduce bird deaths, including the immediate shutdown of the most dangerous 2% of wind turbines and restrictions on winter operation when turbines pose the most danger to raptor and songbird populations. Environmental groups charge that an environmental impact review under the California Environmental Quality Act should have been completed before the permits were issued.
In Maryland, the public services commission took steps in October to implement a renewable portfolio standard that was enacted in 2004. The Maryland renewable portfolio standard separates renewable electric generation into two categories. Tier 1 facilities include solar energy, wind power, qualifying biomass and methane from landfills or wastewater treatment plants. Tier 2 includes waste-to-energy plants, the use of poultry litter as fuel and certain hydroelectric projects. Maryland utilities will be required to supply 1% of their electricity from tier 1 renewable fuels by 2006. The amount will increase to 7.5% by 2019. Utilities will need to provide 2.5% of their electricity from tier 2 sources by 2006.
A draft environmental impact statement completed in October recommends approval of a proposed liquefied natural gas terminal to be built at the Port of Long Beach in California. The Federal Energy Regulatory Commission and the Port of Long Beach jointly prepared the environmental study. The draft impact statement concludes that the proposed LNG terminal is environmentally acceptable. The terminal will have the capacity to supply 10% of the natural gas needs of California.
Finally, EPA published a proposed rule in October that would exempt the reporting of NOx emissions in amounts less than 1,000 pounds per 24 hours under Superfund and the Emergency Planning and Community Right to Know Act, provided the releases are from combustion activities and not accidents or malfunctions. Under those laws, industrial facilities are currently required to report NOx emissions if they exceed 10 pounds during any 24-hour period. Sources usually notify the government of any continuous emissions of NOx that exceed this threshold. The proposed rule will provide some administrative reporting relief to facilities that emit relatively small amounts of NOx.